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1.
The Shoushan Basin is an important hydrocarbon province in the Western Desert, Egypt, but the origin of the hydrocarbons is not fully understood. In this study, organic matter content, type and maturity of the Jurassic source rocks exposed in the Shoushan Basin have been evaluated and integrated with the results of basin modeling to improve our understanding of burial history and timing of hydrocarbon generation. The Jurassic source rock succession comprises the Ras Qattara and Khatatba Formations, which are composed mainly of shales and sandstones with coal seams. The TOC contents are high and reached a maximum up to 50%. The TOC values of the Ras Qattara Formation range from 2 to 54 wt.%, while Khatatba Formation has TOC values in the range 1-47 wt.%. The Ras Qattara and Khatatba Formations have HI values ranging from 90 to 261 mgHC/gTOC, suggesting Types II-III and III kerogen. Vitrinite reflectance values range between 0.79 and 1.12 VRr %. Rock−Eval Tmax values in the range 438-458 °C indicate a thermal maturity level sufficient for hydrocarbon generation. Thermal and burial history models indicate that the Jurassic source rocks entered the mature to late mature stage for hydrocarbon generation in the Late Cretaceous to Tertiary. Hydrocarbon generation began in the Late Cretaceous and maximum rates of oil with significant gas have been generated during the early Tertiary (Paleogene). The peak gas generation occurred during the late Tertiary (Neogene).  相似文献   

2.
Potential source rocks on the Laminaria High, a region of the northern Bonaparte Basin on the North West Shelf of Australia, occur within the Middle Jurassic to Lower Cretaceous early to post-rift sequences. Twenty-two representative immature source rock samples from the Jurassic to Lower Cretaceous (Plover, Laminaria, Frigate, Flamingo and Echuca Shoals) sequences were analysed to define the hydrocarbon products that analogous mature source rocks could have generated during thermal maturation and filled the petroleum reservoirs in the Laminaria High region. Rock-Eval pyrolysis data indicate that all the source rocks contain type II–III organic matter and vary in organic richness and quality. Open system pyrolysis-gas chromatography on extracted rock samples show a dominance of aliphatic components in the pyrolysates. The Plover source rocks are the exception which exhibit high phenolic contents due to their predominant land-plant contribution. Most of the kerogens have the potential to generate Paraffinic–Naphthenic–Aromatic oils with low wax contents. Bulk kinetic analyses reveal a relatively broad distribution of activation energies that are directly related to the heterogeneity in the kerogens. These kinetic parameters suggest different degrees of thermal stability, with the predicted commencement of petroleum generation under geological heating conditions covering a relatively broad temperature range from 95 to 135 °C for the Upper Jurassic−Lower Cretaceous source rocks. Both shales and coals of the Middle Jurassic Plover Formation have the potential to generate oil at relatively higher temperatures (140–145 °C) than those measured for crude oils in previous studies. Hence, the Frigate and the Flamingo formations are the main potential sources of oils reservoired in the Laminaria and Corallina fields. Apart from being a reservoir, the Laminaria Formation also contains organic-rich layers, with the potential to generate oil. For the majority of samples analysed, the compositional kinetic model predictions indicate that 80% of the hydrocarbons were generated as oil and 20% as gas. The exception is the Lower Cretaceous Echuca Shoals Formation which shows the potential to generate a greater proportion (40%) of gas despite its marine source affinity, due to inertinite dominating the maceral assemblage.  相似文献   

3.
Upper Jurassic organic matter-rich, marine shales of the Mandal Formation have charged major petroleum accumulations in the North Sea Central Graben including the giant Ekofisk field which straddles the graben axis. Recent exploration of marginal basin positions such as the Mandal High area or the Søgne Basin has been less successful, raising the question as to whether charging is an issue, possibly related to high thermal stability of the source organic matter or delayed expulsion from source to carrier.The Mandal Formation is in part a very prolific source rock containing mainly Type II organic matter with <12 wt.-% TOC and HI < 645 mg HC/g TOC but Type III-influenced organofacies are also present. The formation is therefore to varying degrees heterogeneous. Here we show, using geochemical mass balance modelling, that the petroleum expulsion efficiency of the Mandal Formation is relatively low as compared to the Upper Jurassic Draupne Formation, the major source rock in the Viking Graben system. Using maturity series of different initial source quality from structurally distinct regions and encompassing depositional environments from proximal to distal facies, we have examined the relationship between free hydrocarbon retention and organic matter structure. The aromaticity of the original and matured petroleum precursors in the Mandal source rock plays a major role in its gas retention capacity as cross-linked monoaromatic rings act on the outer surface of kerogen as sorptive sites. However, oil retention is a function of both kerogen and involatile bitumen compositions. Slight variations in total petroleum retention capacities within the same kerogen yields suggest that texture of organic matter (e.g. organic porosity) could play a role as well.  相似文献   

4.
Significant oil and gas accumulations occur in and around Lougheed Island, Arctic Canada, where hydrocarbon prospectivity is controlled by potential source rock distribution and composition. The Middle to Upper Triassic rocks of the Schei Point Group (e.g. Murray Harbour and Hoyle Bay formations) contain a mixture of Types I and II organic matter (Tasmanales marine algae, amorphous fluorescing bituminite). These source rocks are within the oil generation zone and have HI values up to 600 mg HC/g Corg. The younger source rocks of the Lower Jurassic Jameson Bay and the Upper Jurassic Ringnes formations contain mainly gas-prone Type II/III organic matter and are marginally mature. Vitrinite reflectance profiles suggest an effective geothermal gradient essentially similar to the present-day gradient (20 to 30°C/km). Maturation gradients are low, ranging from 0.125 to 0.185 log%Ro/km. Increases in subsidence rate in the Early Cretaceous suggest that the actual heat flow history was variable and has probably diminished from that time. The high deposition rates of the Christopher Formation shales coincide with the main phase of rifting in Aptian-Albian times. Uplift and increased sediment supply in the Maastrichtian resulted in a new sedimentary and tectonic regime, which culminated in the final phase of the Eurekan Orogeny. Burial history models indicate that hydrocarbon generation in the Schei Point Group took place during rifting in Early Cretaceous, long before any Eurekan deformation.  相似文献   

5.
Structured organic matters of the Palynomorphs of mainly dinoflagellate cysts are used in this study for dating the limestone, black shale, and marl of the Middle Jurassic (Bajocian–Bathonian) Sargelu Formation, Upper Jurassic (Upper Callovian – Lower Oxfordian) Naokelekan Formation, Upper Jurassic (Kimeridgian and Oxfordian) Gotnia and Barsarine Formations, and Upper Jurassic – Lower Cretaceous (Tithonian-Beriassian) Chia Gara source rock Formations while spore species of Cyathidites australis and Glechenidites senonicus are used for maturation assessments of this succession. Materials' used for this palynological study are 320 core and cutting samples of twelve oil wells and three outcrops in North Iraq.Terpane and sterane biomarker distributions, as well as stable isotope values, were determined for oils potential source rock extracts of Jurassic-Lower Cretaceous strata to determine valid oil-to-source rock correlations in North Iraq. Two subfamily carbonate oil types-one of Middle Jurassic age (Sargelu) carbonate rock and the other of mixed Upper Jurassic/Cretaceous age (Chia Gara) with Sargelu sources as well as a different oil family related to Triassic marls, were identified based on multivariate statistical analysis (HCA & PCA). Middle Jurassic subfamily A oils from Demir Dagh oil field correlate well with rich, marginally mature, Sargelu source rocks in well Mk-2 near the city of Baiji. In contrast, subfamily B oils have a greater proportion of C28/C29 steranes, indicating they were generated from Upper Jurassic/Lower Cretaceous carbonates such as those at Gillabat oil field north of Mansuriyah Lake. Oils from Gillabat field thus indicate a lower degree of correlation with the Sargelu source rocks than do oils from Demir Dagh field.Palynofacies assessments are performed for this studied succession by ternary kerogen plots of the phytoclast, amorphous organic matters, and palynomorphs. From the diagram of these plots and maturation analysis, it could be assessed that the formations of Chia Gara and Sargelu are both deposited in distal suboxic to anoxic basin and can be correlated with kerogens classified microscopically as Type A and Type B and chemically as Type II. The organic matter, comprised principally of brazinophyte algae, dinoflagellate cysts, spores, pollen, foraminifera test linings, and phytoclasts in all these formations and hence affected with upwelling current. These deposit contain up to 18 wt% total organic matters that are capable to generate hydrocarbons within mature stage of thermal alteration index (TAI) range in Stalplin's scale (Staplin, 1969) of 2.7–3.0 for the Chia Gara Formation and 2.9–3.1 for the Sargelu Formation. Case study examples of these oil prone strata are; one 7-m (23-ft) thick section of the Sargelu Formation averages 44.2 mg HC/g S2 and 439 °C Tmax (Rock-Eval pyrolysis analyses) and 16 wt% TOC especially in well Mk-2 whereas, one 8-m (26-ft) thick section of the Chia Gara and 1-m (3-ft) section of Naokelekan Formations average 44.5 mg HC/g S2 and 440 °C Tmax and 14 wt% TOC especially in well Aj-8. One-dimension, petroleum system models of key wells using IES PetroMod Software can confirm their oil generation capability.These hydrocarbon type accumulation sites are illustrated in structural cross sections and maps in North Iraq.  相似文献   

6.
As a result of a long-lasting and complex geological history, organic-matter-rich fine-grained rocks (black shales) with widely varying ages can be found on Ukrainian territory. Several of them are proven hydrocarbon source rocks and may hold a significant shale gas potential.Thick Silurian black shales accumulated along the western margin of the East European Craton in a foreland-type basin. By analogy with coeval organic-matter-rich rocks in Poland, high TOC contents and gas window maturity can be expected. However, to date information on organic richness is largely missing and maturity patterns remain to be refined.Visean black shales with TOC contents as high as 8% and a Type III-II kerogen accumulated along the axis of the Dniepr-Donets rift basin (DDB). They are the likely source for conventional oil and gas. Oil-prone Serpukhovian black shales accumulated in the shallow northwestern part of the DDB. Similar black shales probably may be present in the Lviv-Volyn Basin (western Ukraine).Middle Jurassic black shales up to 500 m thick occur beneath the Carpathian Foredeep. They are the likely source for some heavy oil deposits. TOC contents up to 12% (Type II) have been recorded, but additional investigations are needed to study the vertical and lateral variability of organic matter richness and maturity.Lower Cretaceous black shales with a Type III(-II) kerogen (TOC > 2%) are widespread at the base of the Carpathian flysch nappes, but Oligocene black shales (Menilite Fm.) rich in organic matter (4–8% TOC) and containing a Type II kerogen are the main source rock for oil in the Carpathians. Their thermal maturity increases from the external to the internal nappes.Oligocene black shales are also present in Crimea (Maykop Fm.). These rocks typically contain high TOC contents, but data from Ukraine are missing.  相似文献   

7.
The Upper Triassic — Lower Jurassic Kap Stewart Formation (Jameson Land, East Greenland) has been studied by a combination of sedimentological and organic geochemical methods (LECO/Rock Eval, sulphur, gas chromatography) in order to assess the hydrocarbon source potential of the abundant and extensive lacustrine shale intervals present in the formation.The organic matter in the shales is a mixture of algal and higher plant remains (type I and III kerogen). An organic assemblage dominated by algal material, having a rich oil potential, occurs in an interval approximately 10–15 m thick in the uppermost part of the formation. This interval has an organic carbon content up to 10% and Hydrogen Index values up to 700. The interval is consistently traceable along the exposed margins and the central part of the basin. The deposition of the uppermost shale interval coincided with the largest expansion of the lake, during a period with a stratified water column and anoxic bottom-water conditions.Locally the rocks exposed are thermally postmature due to the thermal influence of dolerite sills which intruded the Kap Stewart Formation in Tertiary time. However, the organic-rich shale interval is beyond the influence of the sills and indicates a maturity prior to or in the early stages of oil generation.Calculations of the generative potential of the lacustrine source rocks suggest that significant amounts of petroleum may have been generated in those sediments which have undergone sufficient burial in the southern and central part of the basin. Here, the contemporaneously deposited delta front and barrier island sandstones can thus be considered as potential targets for future hydrocarbon exploration. This type of play may also be of importance in other North Atlantic basins with a similar basin history.  相似文献   

8.
华南陆缘出露的上三叠统-白垩系,累计厚度超过10 000m,露头调查未见油苗,烃源岩主要为泥岩、碳质泥岩和煤线,有机质类型以Ⅱ-Ⅲ型为主。上三叠统小水组,发育较深水的海相、Ⅱ型良好烃源岩,TOC为1.17%～5.43%;下侏罗统桥源组发育海陆过渡环境的Ⅲ型良好烃源岩,TOC为1.36%～10.37%;下侏罗统其他层系(金鸡组、银瓶山组、上龙水组、长埔组、吉水门组)发育浅海-半深海相的中等-好的烃源岩,TOC为0.5%～1.76%。烃源岩均已处于成熟-过成熟阶段。小水组、蓝塘群烃源岩品质良好,厚度巨大,在南海北部海域开展中生界烃源岩研究时,值得重点关注是否有与之相当的烃源岩层系发育。  相似文献   

9.
Palynological and biomarker characteristics of organic facies recovered from Cretaceous–Miocene well samples in the Ras El Bahar Oilfield, southwest Gulf of Suez, and their correlation with lithologies, environments of deposition and thermal maturity have provided a sound basis for determining their source potential for hydrocarbons. In addition to palynofacies analysis, TOC/Rock-Eval pyrolysis, kerogen concentrates, bitumen extraction, carbon isotopes and saturated and aromatic biomarkers enable qualitative and quantitative assessments of sedimentary organic matter to be made. The results obtained from Rock-Eval pyrolysis and molecular biomarker data indicate that most of the samples come from horizons that have fair to good hydrocarbon generation potential in the study area. The Upper Cretaceous–Paleocene-Lower Eocene samples contain mostly Type-II to Type-III organic matter with the capability of generating oil and gas. The sediments concerned accumulated in dysoxic–anoxic marine environments. By contrast, the Miocene rocks yielded mainly Type-III and Type-II/III organic matter with mainly gas-generating potential. These rocks reflect deposition in a marine environment into which there was significant terrigenous input. Three palynofacies types have been recognized. The first (A) consists of Type-III gas-prone kerogen and is typical of the Early–Middle Miocene Belayim, Kareem and upper Rudeis formations. The second (B) has mixed oil and gas features and characterizes the remainder of the Rudeis Formation. The third association (C) is dominated by amorphous organic matter, classified as borderline Type-II oil-prone kerogen, and is typical of the Matulla (Turonian–Santonian) and Wata (Turonian) formations. Rock-Eval Tmax, PI, hopane and sterane biomarkers consistently indicate an immature to early mature stage of thermal maturity for the whole of the studied succession.  相似文献   

10.
Cretaceous sedimentary rocks of the Mukalla, Harshiyat and Qishn formations from three wells in the Jiza sub-basin were studied to describe source rock characteristics, providing information on organic matter type, paleoenvironment of deposition and hydrocarbon generation potential. This study is based on organic geochemical and petrographic analyses performed on cuttings samples. The results were then incorporated into basin models in order to understand the burial and thermal histories and timing of hydrocarbon generation and expulsion.The bulk geochemical results show that the Cretaceous rocks are highly variable with respect to their genetic petroleum generation potential. The total organic carbon (TOC) contents and petroleum potential yield (S1 + S2) of the Cretaceous source rocks range from 0.43 to 6.11% and 0.58–31.14 mg HC/g rock, respectively indicating non-source to very good source rock potential. Hydrogen index values for the Early to Late Cretaceous Harshiyat and Qishn formations vary between 77 and 695 mg HC/g TOC, consistent with Type I/II, II-III and III kerogens, indicating oil and gas generation potential. In contrast, the Late Cretaceous Mukalla Formation is dominated by Type III kerogen (HI < 200 mg HC/g TOC), and is thus considered to be gas-prone. The analysed Cretaceous source rock samples have vitrinite reflectance values in the range of 0.37–0.95 Ro% (immature to peak-maturity for oil generation).A variety of biomarkers including n-alkanes, regular isoprenoids, terpanes and steranes suggest that the Cretaceous source rocks were deposited in marine to deltaic environments. The biomarkers also indicate that the Cretaceous source rocks contain a mixture of aquatic organic matter (planktonic/bacterial) and terrigenous organic matter, with increasing terrigenous influence in the Late Cretaceous (Mukalla Formation).The burial and thermal history models indicate that the Mukalla and Harshiyat formations are immature to early mature. The models also indicate that the onset of oil-generation in the Qishn source rock began during the Late Cretaceous at 83 Ma and peak-oil generation was reached during the Late Cretaceous to Miocene (65–21 Ma). The modeled hydrocarbon expulsion evolution suggests that the timing of oil expulsion from the Qishn source rock began during the Miocene (>21 Ma) and persisted to present-day. Therefore, the Qishn Formation can act as an effective oil-source but only limited quantities of oil can be expected to have been generated and expelled in the Jiza sub-basin.  相似文献   

11.
The objectives of our study were to assess the thickness, lateral extent, organic richness and maturity of the potential source rocks in Hungary and to estimate the volumes of hydrocarbons generated, in order that potential shale gas and shale oil plays could be identified and characterised.The Upper Triassic Kössen Marl in south-west Hungary could represent the best potential shale gas/shale oil play, due to its high organic richness, high maturity and the presence of fracture barriers. The area of gas- and oil-generative maturity is around 720 km2 with the unexpelled petroleum estimated to be up to 9 billion barrel oil-equivalent.The Lower Jurassic sediments of the Mecsek Mountains and under the Great Plain contain fair quality gas-prone source rocks, with low shale gas potential, except for a thin Toarcian shale unit which is richer in organic matter. The latter could form a potential shale gas play under the Great Hungarian Plain, if it is thicker locally.The Lower Oligocene Tard Clay in north-east Hungary could represent the second best potential shale oil play, due to its organic richness, favourable maturity and large areal extent (4500 km2) with around 7 billion barrel oil-equivalent estimated in-place volume of petroleum.Middle Miocene marine formations could represent locally-developed shale gas plays; they have fair amounts of organic matter and a mixture of type II/III kerogen, but their vertical and lateral variability is high.The Upper Miocene lacustrine Endrőd Marl contains less organic matter and the kerogen is mainly type III, which is not favourable for shale gas generation. The high carbonate and clay content, plus the lack of upper and lower fracture barriers would represent additional production challenges.  相似文献   

12.
Deposition of organic rich black shales and dark gray limestones in the Berriasian-Turonian interval has been documented in many parts of the world. The Early Cretaceous Garau Formation is well exposed in Lurestan zone in Iran and is composed of organic-rich shales and argillaceous limestones. The present study focuses on organic matter characterization and source rock potential of the Garau Formations in central part of Lurestan zone. A total of 81 core samples from 12 exploratory wells were subjected to detailed geochemical analyses. These samples have been investigated to determine the type and origin of the organic matter as well as their petroleum-generation potential by using Rock-Eval/TOC pyrolysis, GC and GCMS techniques. The results showed that TOC content ranges from 0.5 to 4.95 percent, PI and Tmax values are in the range of 0.2 and 0.6, and 437 and 502 °C. Most organic matter is marine in origin with sub ordinary amounts of terrestrial input suggesting kerogen types II-III and III. Measured vitrinite reflectance (Rrandom%) values varying between 0.78 and 1.21% indicating that the Garau sediments are thermally mature and represent peak to late stage of hydrocarbon generation window. Hydrocarbon potentiality of this formation is assessed fair to very good capable of generating chiefly gas and some oil. Biomarker characteristics are used to provide information about source and maturity of organic matter input and depositional environment. The relevant data include normal alkane and acyclic isoprenoids, distribution of the terpane and sterane aliphatic biomarkers. The Garau Formation is characterized by low Pr/Ph ratio (<1.0), high concentrations of C27 regular steranes and the presence of tricyclic terpanes. These data indicated a carbonate/shale source rock containing a mixture of aquatic (algal and bacterial) organic matter with a minor terrigenous organic matter contribution that was deposited in a marine environment under reducing conditions. The results obtained from biomarker characteristics also suggest that the Garau Formation is thermally mature which is in agreement with the results of Rock-Eval pyrolysis.  相似文献   

13.
The Upper Jurassic marlstones (Mikulov Fm.) and marly limestones (Falkenstein Fm.) are the main source rocks for conventional hydrocarbons in the Vienna Basin in Austria. In addition, the Mikulov Formation has been considered a potential shale gas play. In this paper, organic geochemical, petrographical and mineralogical data from both formations in borehole Staatz 1 are used to determine the source potential and its vertical variability. Additional samples from other boreholes are used to evaluate lateral trends. Deltaic sediments (Lower Quarzarenite Member) and prodelta shales (Lower Shale Member) of the Middle Jurassic Gresten Formation have been discussed as secondary sources for hydrocarbons in the Vienna Basin area and are therefore included in the present study.The Falkenstein and Mikulov formations in Staatz 1 contain up to 2.5 wt%TOC. The organic matter is dominated by algal material. Nevertheless, HI values are relative low (<400 mgHC/gTOC), a result of organic matter degradation in a dysoxic environment. Both formations hold a fair to good petroleum potential. Because of its great thickness (∼1500 m), the source potential index of the Upper Jurrasic interval is high (7.5 tHC/m2). Within the oil window, the Falkenstein and Mikulov formations will produce paraffinic-naphtenic-aromatic low wax oil with low sulfur content. Whereas vertical variations are minor, limited data from the deep overmature samples suggest that original TOC contents may have increased basinwards. Based on TOC contents (typically <2.0 wt%) and the very deep position of the maturity cut-off values for shale oil/gas production (∼4000 and 5000 m, respectively), the potential for economic recovery of unconventional petroleum is limited. The Lower Quarzarenite Member of the Middle Jurassic Gresten Formation hosts a moderate oil potential, while the Lower Shale Member is are poor source rock.  相似文献   

14.
Geochemical characteristics of organic matter in the profiles of Dukla, Silesian, Sub-Silesian and Skole units of the Polish Outer Carpathians and of the Palaeozoic–Mesozoic basement in the Dębica-Rzeszów-Leżajsk-Sanok area were established based on Rock-Eval, vitrinite reflectance, isotopic and biomarker analyses of 485 rock samples. The Oligocene Menilite beds have the best hydrocarbon potential of all investigated formations within the Dukla, Silesian, and Skole units. The Ordovician, Silurian, Lower Devonian and locally Middle Jurassic strata of the Palaeozoic–Mesozoic basement are potential source rocks for oil and gas accumulated in Palaeozoic and Mesozoic reservoirs. Thirty one natural gas samples from sandstone reservoirs of the Lower Cretaceous-Lower Miocene strata within the Outer Carpathian sequence and eight from sandstone and carbonate reservoirs of the Palaeozoic–Mesozoic basement were analysed for molecular and isotopic compositions to determine their origin. Natural gases accumulated both in the Outer Carpathian and the Palaeozoic–Mesozoic basement reservoirs are genetically related to thermogenic and microbial processes. Thermogenic gaseous hydrocarbons that accumulated in the Dukla and Silesian units were generated from the Menilite beds. Thermogenic gaseous hydrocarbons that accumulated in the Sub-Silesian Unit most probably migrated from the Silesian Unit. Initial, and probably also secondary microbial methane component has been generated during microbial carbon dioxide reduction within the Oligocene Menilite beds in the Dukla Unit and Oligocene-Lower Miocene Krosno beds in the Silesian Unit. Natural gases that accumulated in traps within the Middle Devonian, Mississippian, Upper Jurassic, and Upper Cretaceous reservoirs of the Palaeozoic–Mesozoic basement were mainly generated during thermogenic processes and only sporadically from initial microbial processes. The thermogenic gases were generated from kerogen of the Ordovician-Silurian and Middle Jurassic strata. The microbial methane component occurs in a few fields of the Dukla and Silesian units and in the two accumulations in the Middle Devonian reservoirs of the Palaeozoic–Mesozoic basement.  相似文献   

15.
Natural gas samples from two gas fields located in Eastern Kopeh-Dagh area were analyzed for molecular and stable isotope compositions. The gaseous hydrocarbons in both Lower Cretaceous clastic reservoir and Upper Jurassic carbonate reservoir are coal-type gases mainly derived from type III kerogen, however enriched δD values of methane implies presence of type II kerogen related material in the source rock. In comparison Upper Jurassic carbonate reservoir gases show higher dryness coefficient resulted through TSR, while presence of C1C5 gases in Lower Cretaceous clastic reservoir exhibit no TSR phenomenon. Carbon isotopic values indicate gas to gas cracking and TSR occurrence in the Upper Jurassic carbonate reservoir, as the result of elevated temperature experienced, prior to the following uplifts in last 33–37 million years. The δ13C of carbon dioxide and δ34S of hydrogen sulfide in Upper Jurassic carbonate reservoir do not primarily reflect TSR, as uplift related carbonate rock dissolution by acidic gases and reaction/precipitation of light H2S have changed these values severely. Gaseous hydrocarbons in both reservoirs exhibit enrichment in C2 gas member, with the carbonate reservoir having higher values resulted through mixing with highly-mature-completely-reversed shale gases. It is likely that the uplifts have lifted off the pressure on shale gases, therefore facilitated the migration of the gases into overlying horizons. However it appears that the released gases during the first major uplift (33–37 million years ago) have migrated to both reservoirs, while the second migrated gases have only mixed with Upper Jurassic carbonate reservoir gases. The studied data suggesting that economic accumulations of natural gas/shale gases deeper than Upper Jurassic carbonate reservoir would be unlikely.  相似文献   

16.
The Western Desert of Egypt is one of the world’s most prolific Jurassic and Cretaceous hydrocarbon provinces. It is one of many basins that experienced organic-rich sedimentation during the late Cenomanian/early Turonian referred to as oceanic anoxic event 2 (OAE2). The Razzak #7 oil well in the Razzak Field in the northern part of the Western Desert encountered the Upper Cretaceous Abu Roash Formation. This study analyzed 23 samples from the upper “G”, “F”, and lower “E” members of the Abu Roash Formation for palynomorphs, particulate organic matter, total organic carbon (TOC) and δ13Corg in order to identify the OAE2, determine hydrocarbon source rock potential, and interpret the depositional environment. The studied samples are generally poor in palynomorphs, but show a marked biofacies change between the lower “E” member and the rest of the studied samples. Palynofacies analysis (kerogen quality and quantity) indicates the presence of oil- and gas-prone materials (kerogen types I and II/III, respectively), and implies reducing marine paleoenvironmental conditions. Detailed carbon stable isotopic and organic carbon analyses indicate that fluctuations in the δ13Corg profile across the Abu Roash upper “G”, “F”, and lower “E” members correspond well with changes in TOC values. A positive δ13Corg excursion (∼2.01‰) believed to mark the short-term global OAE2 was identified within the organic-rich shaly limestone in the basal part of the Abu Roash “F” member. This excursion also coincides with the peak TOC measurement (24.61 wt.%) in the samples.  相似文献   

17.
Source rock studies are one of the key issues of petroleum exploration activities. In the supercontinent of Gondwana, ice ages related to the Upper Ordovician (Hirnantian) and rising sea levels caused by glacial melting at the end of the Ordovician and Early Silurian (Llandoverian) created excellent source rocks along the margin of Gondwana. Investigations conducted in the Arabian Peninsula have been indicated indicating that the lower Qalibah Formation (the so-called Qusaiba Member or Hot Shale) is a good source rock for the Paleozoic petroleum system in this area. Likewise, the Sarchahan Formation was recently introduced as a source rock in the Zagros Basin of Iran, which is probably equivalent to the Qalibah Formation in the Arabian Peninsula. In this study, samples were prepared from surface and subsurface Paleozoic rock units in Iran's Zagros Basin. The emphasis of the paper was on the Sarchahan Formation in Kuh-e Faraghan, ranging in age from the Late Ordovician (Hirnantian) to Lower Silurian (Llandoverian) to determine whether the high richness of organic matter in the Sarchahan Formation is related to the Late Ordovician or Lower Silurian. The basal part of the Sarchahan Formation belongs to the Late Ordovician (Hirnantian) because of the presence of the persculptus graptolite biozone, while the remainder belongs to the Lower Silurian. The Ordovician and early Llandoverian parts of the Sarchahan Formation contain type II and III kerogen with TOC ranging from 2.94 to 7.19, but the rest of the Sarchahan Formation (late Llandoverian) has TOC ranging from 0.1 to 0.58. Therefore, the Hot Shale in Iran falls within the Hirnantian and early Llandoverian (Rhuddanian), and not the latest Llandoverian (Aeronian and Telychian). Utilizing organic petrography, kerogen type was found II/III. The carbon stable isotope studies revealed that the source rock of hydrocarbons in Dalan and Kangan reservoirs has been the Sarchahan Formation. Based on analytical data, the kerogenous shales in the lower part of the Sarchahan Formation are at end of gas window, and the gamma ray amount is approximately 180 API. This research indicates the differences between the source rocks in the southern and northern Persian Gulf and suggesting, the Hot Shale should be considered in different views and used in modeling studies of sedimentary basins for future exploration targets.  相似文献   

18.
鄂尔多斯盆地北部主力气源岩太原组、山西组煤系地层热成熟史的研究对本区天然气充注过程和有利目标区预测具有重要的参考价值。在对研究区烃源岩评价和一维、二维地质建模研究的基础上。利用BasinMod盆地模拟软件对单井以及研究区内二维剖面、平面进行了煤系烃源岩热演化史模拟研究。研究结果表明：（1）该区在中三叠世进入生烃门限，中侏罗世以后，烃源岩持续埋深，早白垩世末期至最大埋深（4000m左右），绝大多数的天然气都在这一阶段生成，早白垩世末构造抬升以后只有少量天然气生成；（2）研究区上古生界太原组和山西组煤系源岩最大累积生烃强度可达到2200×10^8m^3／km^2，对现今天然气的分布具有较强的控制作用。  相似文献   

19.
The regional burial history pattern, thermal maturity variations and source rock assessment of the sedimentary succession in the eastern Taurus region, in the southern part of Turkey, have been studied on surface samples collected from the six different sections which represent the entire region. Organic petrography (Thermal Alteration Index) and geochemical data (TOC content, Tmax and HI values) were obtained from transmitted-light microscopy and Rock-Eval pyrolysis.The Lower Paleozoic (Cambrian, Ordovician and Silurian) strata were not investigated and modeled in terms of the maturity and hydrocarbon source rock potential, because of their poor organic matter content and their over maturity resulting from great burial depth (more than 7630 m). Other Paleozoic strata, except the Lower Devonian Ayitepesi Formation, generally have the values of more than 0.5% TOC. Organic matter of the Middle Devonian Safaktepesi sediments are composed of highly terrestrial organic material (type III kerogen), while samples from other three formations (Gumusali, Ziyarettepe and Yigilitepe Formations), while samples from other organic matter (type II and type III kerogen). The average TAI values are as high as 3.4 (equivalent to 1.42 of R0%) for Ayitepesi and as low as 2.75 (equivalent to 0.77 of R0%) for Yigilitepe Formations. Time-temperature index values (TTI) indicate that Ziyarettepe and Yigilitepe sediments are marginally mature to mature, while the Devonian strata are overmature. There are minor discrepancies between ΣTTI values and geochemical data in terms of the organic maturity for Devonian strata. In contrast, the e is a consistency between those values for the Ziyarettepe and the Yigilitepe Formations. The onset of oil generation time in the region was initiated from as early as the Norian (216 Ma) to as late as the Lutetian (45 Ma).Regional variations in the level of thermal and source-rock maturities of the Upper Paleozoic sediments in the eastern Taurus region largely depend on burial depth.  相似文献   

20.
A reconnaissance study of potential hydrocarbon source rocks of Paleozoic to Cenozoic age from the highly remote New Siberian Islands Archipelago (Russian Arctic) was carried out. 101 samples were collected from outcrops representing the principal Paleozoic-Cenozoic units across the entire archipelago. Organic petrological and geochemical analyses (vitrinite reflectance measurements, Rock-Eval pyrolysis, GC-MS) were undertaken in order to screen the maturity, quality and quantity of the organic matter in the outcrop samples. The lithology varies from continental sedimentary rocks with coal particles to shallow marine carbonates and deep marine black shales. Several organic-rich intervals were identified in the Upper Paleozoic to Lower Cenozoic succession. Lower Devonian shales were found to have the highest source rock potential of all Paleozoic units. Middle Carboniferous-Permian and Triassic units appear to have a good potential for natural gas formation. Late Mesozoic (Cretaceous) and Cenozoic low-rank coals, lignites, and coal-bearing sandstones also display a potential for gas generation. Kerogen type III (humic, gas-prone) dominates in most of the samples, and indicates deposition in lacustrine to coastal paleoenvironments. Most of the samples (except some of Cretaceous and Paleogene age) reached oil window maturities, whereas the Devonian to Carboniferous units shared a maturity mainly within the gas window.  相似文献   

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